Actionable news
0
All posts from Actionable news
Actionable news in SU: SUNCOR ENERGY Inc,

2 Suncor Energy Inc 2015 THIRD QUARTER

The following excerpt is from the company's SEC filing.

"We believe that we can drive real improvements in Syncrude's performance with a larger ownership interest," said Williams. "We have been disappointed with Syncrude's performance for some time now. The asset ran at only 67% of capacity during the third quarter, and about 70% so far this year, in stark contrast to Suncor's upgrading operations that have been consistently achieving above 90% reliability this year."

The company also completed an asset swap and lease with TransAlta Corporation where Suncor assumed operating control of the Poplar Creek cogeneration facilities, which provide steam and power to th e company's Oil Sands operations, in exchange for Suncor's Kent Breeze and its share of the Wintering Hills wind power facilities. Bringing the Poplar Creek assets in-house is expected to improve Suncor's overall Oil Sands operations reliability and profitability.

The National Energy Board approved the start-up of Enbridge's Line 9 reversal in the third quarter of 2015, which is anticipated in the fourth quarter of 2015. The reversal is expected to provide Suncor with the flexibility to supply the Montreal refinery with a full slate of inland-priced crude from Western Canada.

Oil Sands Operations

Suncor continued to focus on well pad construction to sustain existing production at Firebag and MacKay River, and on multiple projects that enhance safety, reliability and environmental performance. Capital spending in the third quarter included major maintenance on a vacuum unit and one Upgrader 2 coker set, that was completed in the fourth quarter of 2015.

Oil Sands Ventures

The Fort Hills project remains on schedule with detailed engineering 94% complete and construction 43% complete at the end of the third quarter. Spending during the quarter included engineering, procurement, module fabrication and site construction. The project is expected to deliver approximately 73,000 bbls/d of bitumen to Suncor, increasing to 91,000 bbls/d subject to closing of an additional 10% working interest in Fort Hills. First oil is expected in the fourth quarter of 2017, and 90% of capacity planned to be reached within twelve months thereafter.

Exploration and Production

Construction of the Hebron project continued in the third quarter of 2015, with first oil expected in late 2017. Development drilling at Golden Eagle continued through the third quarter.

SUNCOR ENERGY INC.

2015 THIRD QUARTER

Operating Earnings Reconciliation

Three months ended

September 30

Nine months ended

($ millions)

2015

2014

Net (loss) earnings

Unrealized foreign exchange loss on U.S. dollar denominated debt

Impact of income tax rate adjustments on deferred taxes

Gain on significant disposal

Restructuring charges

Insurance proceeds

Impairments

Reserves redetermination

Income tax charge

Operating earnings

Operating earnings is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.

Adjustments to the company's deferred income taxes from a 12% decrease in the U.K. tax rate on oil and gas profits from the North Sea in the first quarter of 2015 of $406 million, and a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015 of $423 million.

After-tax gain related to the sale of the company's Wilson Creek natural gas assets in the third quarter of 2014 and the after-tax gain related to the sale of the company's share of certain assets and liabilities of Pioneer Energy in the Refining and Marketing segment in the second quarter of 2015.

Restructuring charges related to cost reduction initiatives in the Corporate segment.

Business interruption insurance proceeds for the Terra Nova asset in the E&P segment.

After-tax impairment charges of $718 million on the company's interest in the Joslyn mining project, $297 million against the company's Libyan assets, and $223 million related to certain assets in the Oil Sands segment following a review of repurpose options due to previously revised growth strategies.

Reserves redetermination of 1.2 million barrels of oil receivable related to an interest in a Norwegian asset that Suncor previously owned.

Represents a current income tax and associated interest charge recorded in the third quarter of 2014 related to the timing of tax depreciation deductions taken on certain capital expenditures incurred in a prior period in the Oil Sands segment.

Corporate Guidance

Suncor has updated assumptions provided for in its 2015 corporate guidance, previously issued on July 29, 2015. The following 2015 full year outlook assumptions have been adjusted: Brent at Sullom Voe to US$55/bbl from US$60/bbl, WTI at Cushing to US$50/bbl from US$54/bbl, WCS at Hardisty to US$37/bbl from US$40/bbl, and the International tax rate has changed from 30%35% to 10%15%. For further details and advisories regarding Suncor's 2015 revised corporate guidance, see www.suncor.com/guidance.

Measurement Conversions

Certain natural gas volumes in this report to shareholders have been converted to boe on the basis of one bbl to six mcf. See the Advisories section of the MD&A.

4 SUNCOR ENERGY INC.

2015 THIRD QUARTER

MANAGEMENT'S DISCUSSION AND ANALYSIS

October 28, 2015

Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. We are strategically focused on developing one of the world's largest petroleum resource basins Canada's Athabasca oil sands. In addition, we explore for, acquire, develop, produce and market crude oil and natural gas in Canada and internationally; we transport and refine crude oil, we develop renewable energy, and we market petroleum and petrochemical products primarily in Canada. Periodically, we market third-party petroleum products. We also conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas and byproducts.

For a description of Suncor's segments, refer to Suncor's Management's Discussion and Analysis for the year ended December 31, 2014, dated February 26, 2015 (the 2014 annual MD&A).

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's unaudited interim Consolidated Financial Statements for the three-month and nine-month periods ended September 30, 2015, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2014 and the 2014 annual MD&A.

Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and Suncor's Annual Information Form dated February 26, 2015 (the 2014 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this document, and is not incorporated into this document by reference.

References to "we", "our", "Suncor", or "the company" mean Suncor Energy Inc. and the company's subsidiaries and interests in associates and jointly controlled entities, unless the context otherwise requires.

Table of Contents

Third Quarter Highlights

Consolidated Financial Information

Segment Results and Analysis

Capital Investment Update

Financial Condition and Liquidity

Quarterly Financial Data

Other Items

Common Abbreviations

Forward-Looking Information

1. ADVISORIES

Basis of Presentation

Unless otherwise noted, all financial information has been prepared in accordance with Canadian generally accepted accounting principles (GAAP), specifically International Accounting Standard (IAS) 34

Interim Financial Reporting

as issued by the International Accounting Standards Board, which is within the framework of International Financial Reporting Standards (IFRS).

All financial information is reported in Canadian dollars, unless otherwise noted. Production volumes are presented on a working-interest basis, before royalties, unless otherwise noted. Certain prior year amounts in the Consolidated Statements of Comprehensive Income have been reclassified to conform to the current year's presentation.

Certain financial measures in this MD&A namely operating earnings, cash flow from operations, return on capital employed (ROCE), Oil Sands cash operating costs, free cash flow, and last-in, first-out (LIFO) are not prescribed by GAAP. Operating earnings, Oil Sands cash operating costs and LIFO are defined in the Non-GAAP Financial Measures Advisory section of this MD&A and reconciled to GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A. Cash flow from operations, ROCE and free cash flow are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of this MD&A.

Risk Factors and Forward-Looking Information

The company's financial and operational performance is potentially affected by a number of factors, including, but not limited to, the factors described within the Forward-Looking Information section of this MD&A. This MD&A contains forward-looking information based on Suncor's current expectations, estimates, projections and assumptions. This information is provided to assist readers in understanding the company's future plans and expectations and may not be appropriate for other purposes. Refer to the Forward-Looking Information section of this MD&A for information on the material risk factors and assumptions underlying our forward-looking information.

Certain crude oil and natural gas liquids volumes have been converted to mcfe on the basis of one bbl to six mcf. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Any figure presented in mcfe, boe or mboe may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or natural gas liquids to six mcf of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, conversion on a 6:1 basis may be misleading as an indication of value.

For a list of abbreviations that may be used in this MD&A, refer to the Common Abbreviations section of this MD&A.

6 SUNCOR ENERGY INC.

2. THIRD QUARTER HIGHLIGHTS

Third quarter financial results.

Net loss for the third quarter of 2015 was $376 million, compared to net earnings of $919 million in the prior year quarter. Net loss for the third quarter of 2015 included an unrealized after-tax foreign exchange loss on the revaluation of U.S. dollar denominated debt of $786 million. Net earnings in the prior year quarter included an after-tax gain of $61 million on the disposal of the Wilson Creek assets in the Exploration and Production (E&P) segment, offset by a $54 million income tax and interest charge related to a prior period in the Oil Sands segment, and the impact of an unrealized after-tax foreign exchange loss of $394 million.

for the third quarter of 2015 were $410 million, compared to $1.306 billion for the prior year quarter. The decrease was driven by significantly lower upstream price realizations, partially offset by increased E&P and Oil Sands operations production, a favourable downstream pricing environment, stronger refinery utilizations, lower operating costs and lower royalties compared to the prior year quarter.

Cash flow from operations

was $1.882 billion for the third quarter of 2015, compared to $2.280 billion for the third quarter of 2014. The decrease was largely due to the same factors that impacted operating earnings. Free cash flow

was $467 million for the twelve months ended September 30, 2015, compared to $3.082 billion for the twelve months ended September 30, 2014.

(excluding major projects in progress) decreased to 5.1% for the twelve months ended September 30, 2015, compared to 9.4% for the twelve months ended September 30, 2014.

Higher downstream benchmark crack spreads and stronger refinery utilizations drove operating earnings of $613 million for the Refining and Marketing segment in the quarter.

Going forward, the reversal of Enbridge's Line 9 is expected to provide Suncor with the flexibility to supply the Montreal refinery with a full slate of inland-priced crude from Western Canada.

Oil Sands operations cash operating costs

averaged $27.00/bbl for the quarter, compared to $31.10/bbl in the prior year quarter.

Increased production, lower natural gas prices and a continued focus on cost reductions drove the lowest cash operating costs per barrel in eight years.

Strong Oil Sands operations production despite the impact of planned maintenance.

Oil Sands operations production of 430,300 bbls/d and SCO production of 314,900 bbls/d demonstrate Suncor's commitment to deliver reliable operations.

Suncor demonstrates its commitment to its core business through further investment in the oil sands.

The company announced an agreement to acquire an additional 10% of the Fort Hills mining project and, subsequent to the quarter end, commenced an offer to acquire all of the outstanding shares of Canadian Oil Sands Limited (COS) for consideration of 0.25 of a Suncor share per COS share. The transaction was valued at $6.6 billion at the time of announcement.

Suncor continued to return cash to shareholders.

Suncor returned $419 million to shareholders through dividends, which included a dividend increase to $0.29 per share announced in the second quarter of 2015, and $40 million in share repurchases in the third quarter of 2015.

Operating earnings, cash flow from operations, free cash flow, ROCE and Oil Sands cash operating costs are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

3. CONSOLIDATED FINANCIAL INFORMATION

Financial Highlights

Corporate, Energy Trading and Eliminations

(2 021

Operating earnings (loss)

Cash flow from (used in) operations

Capital and Exploration Expenditures

Sustaining

Growth

Twelve months ended

Free Cash Flow

Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Excludes capitalized interest.

8 SUNCOR ENERGY INC.

Operating Highlights

Production volumes by segment

Oil Sands (mbbls/d)

Exploration and Production (mboe/d)

Production mix

Crude oil and liquids / natural gas (%)

Refinery utilization (%)

Refinery crude oil processed (mbbls/d)

Net Earnings

Suncor's consolidated net loss for the third quarter of 2015 was $376 million, compared with net earnings of $919 million for the prior year quarter. Net earnings for the first nine months of 2015 were $12 million, compared to $2.615 billion in the prior year period. Net earnings were primarily affected by the same factors that influenced operating earnings described subsequently in this section of this MD&A. Other items affecting net earnings over these periods included:

The after-tax unrealized foreign exchange losses on the revaluation of U.S. dollar denominated debt were $786 million for the third quarter of 2015 and $1.548 billion for the first nine months of 2015; the after-tax unrealized foreign exchange losses on the revaluation of U.S. dollar denominated debt were $394 million for the third quarter of 2014 and $420 million for the first nine months of 2014.

In the second quarter of 2015, the company recorded a $423 million deferred income tax charge related to a 2% increase in the Alberta corporate income tax rate.

In the second quarter of 2015, the company recorded an after-tax gain of $68 million on the disposal of the company's share of certain assets and liabilities of Pioneer Energy in the Refining and Marketing segment.

In the first quarter of 2015, the U.K. government enacted a decrease in the supplementary charge rate on oil and gas profits in the North Sea that reduced the statutory tax rate on Suncor's earnings in the U.K. from 62% to 50%. The company revalued its deferred income tax balances, resulting in a one-time decrease to deferred income taxes of $406 million.

In the first quarter of 2015, the company recorded after-tax insurance proceeds of $75 million related to a claim on the Terra Nova asset in the E&P segment.

In the first quarter of 2015, the company recorded after-tax restructuring charges of $57 million related to cost reduction initiatives in the Corporate segment.

In the third quarter of 2014, the company recorded an after-tax gain of $61 million relating to the sale of its Wilson Creek natural gas assets in the E&P segment.

In the third quarter of 2014, the company recorded a current income tax expense adjustment and associated interest expense of $54 million related to the timing of tax depreciation deductions taken on certain capital expenditures incurred in a prior period in the Oil Sands segment.

In the second quarter of 2014, Total E&P Canada Ltd. (Total E&P), the operator of the Joslyn mining project, together with Suncor and the other co-owners of the project agreed to scale back certain development activities in order to focus on engineering studies to further optimize the Joslyn project development plan. As a result of Suncor's assessment of expected future net cash flows and the uncertainty of the project, including the timing of the development plans, Suncor recorded an after-tax charge to net earnings of $718 million against property, plant and equipment and exploration and evaluation assets.

In the second quarter of 2014, as a result of the continued closure of certain Libyan export terminals and the company's view on production plans during the remaining term of the production sharing agreements, the company

recorded an after-tax impairment charge of $297 million against property, plant and equipment and exploration and evaluation assets.

In the second quarter of 2014, the company recorded after-tax impairment charges of $223 million in Oil Sands following a review of certain assets that no longer fit with Suncor's previously revised growth strategies and which could not be repurposed or otherwise deployed. Such assets included a pipeline and related compressor, as well as steam generator components.

In the second quarter of 2014, the company recorded after-tax earnings of $32 million related to an agreement reached for Suncor to receive a reserves redetermination of 1.2 million barrels of oil related to an interest in a Norwegian asset that Suncor previously owned.

(1)(2)

Refer to net earnings discussion above for descriptions of the adjustments.

For an explanation of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this MD&A.

10 SUNCOR ENERGY INC.

Suncor's consolidated operating earnings for the third quarter of 2015 decreased to $410 million, compared to $1.306 billion for the prior year quarter, primarily due to significantly lower upstream price realizations consistent with the decline in benchmark crude prices. The decrease was partially offset by increased E&P and Oil Sands operations production, a favourable downstream pricing environment, stronger refinery utilization, lower operating costs, and lower royalties resulting from the decrease in crude oil prices, compared to the prior year quarter.

Suncor's consolidated operating earnings were $1.491 billion for the first nine months of 2015, compared to $4.234 billion for the prior year period. The decrease was primarily due to the significantly lower upstream price realizations consistent with the decline in benchmark crude prices, partially offset by strong Oil Sands operations production due to improved reliability, a strong downstream pricing environment and lower operating costs.

After-Tax Share-Based Compensation Expense (Recovery) by Segment

Total share-based compensation expense (recovery)

The after-tax share-based compensation expense increased to $77 million during the third quarter of 2015, compared to a recovery of $33 million during the prior year quarter, as a result of an increase in the company's share price.

Business Environment

Commodity prices, refining crack spreads and foreign exchange rates are important factors that affect the results of Suncor's operations.

Average for three months ended

Average for nine months ended

WTI crude oil at Cushing

US$/bbl

ICE Brent crude oil at Sullom Voe

103.40

107.00

Dated Brent/Maya crude oil FOB price differential

MSW at Edmonton

Cdn$/bbl

101.15

Light/heavy differential for WTI at Cushing less WCS at Hardisty

Condensate at Edmonton

100.40

Natural gas (Alberta spot) at AECO

Cdn$/mcf

Alberta Power Pool Price

Cdn$/MWh

New York Harbor 3-2-1 crack

Chicago 3-2-1 crack

Portland 3-2-1 crack

Gulf Coast 3-2-1 crack

Exchange rate

US$/Cdn$

Exchange rate (end of period)

3-2-1 crack spreads are indicators of the refining margin generated by converting three barrels of WTI into two barrels of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

Suncor's sweet SCO price realizations are influenced primarily by the price of WTI at Cushing and by the supply and demand for sweet SCO from Western Canada. Price realizations in the third quarter of 2015 for sweet SCO were negatively affected by a lower WTI price of US$46.45/bbl, compared to US$97.20/bbl in the prior year quarter, partially offset by a lower differential for SCO relative to WTI. Suncor produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton and WCS at Hardisty decreased in the third quarter of 2015 to $52.35/bbl and US$33.25/bbl, respectively, compared to $97.45/bbl and US$77.00/bbl, respectively, in the prior year quarter, resulting in lower price realizations for sour SCO.

Bitumen production that Suncor does not upgrade is blended with diluent or SCO to facilitate delivery on pipeline systems. Net bitumen price realizations are therefore influenced by both prices for Canadian heavy crude oil (WCS at Hardisty is a common reference), prices for diluent (Condensate at Edmonton) and SCO. Bitumen price realizations can also be affected by bitumen quality and spot sales.

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude pricing decreased to an average of US$51.20/bbl in the third quarter of 2015, compared to US$103.40/bbl in the prior year quarter.

Natural gas used in Suncor's Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark decreased to $2.90/mcf in the third quarter of 2015, from $4.00/mcf in the prior year quarter.

Suncor's refining margins are influenced primarily by 3-2-1 crack spreads, which are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates, and by light/heavy and light/sour crude differentials. More complex refineries can earn greater refining margins by processing less expensive, heavier crudes.

12 SUNCOR ENERGY INC.

Crack spreads do not necessarily reflect the margins of a specific refinery. Crack spreads are based on current crude feedstock prices whereas actual refining margins are based on first in, first out (FIFO) inventory accounting, where a delay exists between the time that feedstock is purchased and when it is processed and sold to a third party. FIFO losses normally reflect a declining price environment for crude oil and finished products, whereas FIFO gains reflect an increasing price environment for crude oil and finished products. Specific refinery margins are further impacted by actual crude purchase costs, refinery configuration and refined products sales markets unique to that refinery.

Excess electricity produced in Suncor's Oil Sands business is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the cash operating cost per barrel metric. The Alberta power pool price decreased to an average of $26.05/MWh in the third quarter of 2015 from $63.90/MWh in the prior year quarter.

The majority of Suncor's revenue from the sale of oil and natural gas commodities are based on prices that are determined by or referenced to U.S. dollar benchmark prices. The majority of Suncor's expenditures are realized in Canadian dollars. In the third quarter of 2015, the Canadian dollar weakened in relation to the U.S. dollar as the average exchange rate decreased to US$0.76 per one Canadian dollar from US$0.92 per one Canadian dollar in the prior year quarter. This rate decrease had a positive impact on price realizations for the company during the third quarter.

Suncor also has assets and liabilities, notably most of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. A decrease in the value of the Canadian dollar relative to the U.S. dollar from the previous balance sheet date increases the amount of Canadian dollars required to settle U.S. dollar denominated obligations.

4. SEGMENT RESULTS AND ANALYSIS

OIL SANDS

Septemer 30

Gross revenues

11 723

Less: Royalties

Operating revenues, net of royalties

10 848

Adjusted for:

Impairment of Joslyn mining project and other assets

Operating (loss) earnings

Oil Sands ventures

Adjustment to the company's deferred income taxes resulting from a 2% increase in the Alberta corporate income tax rate in Q2 2015.

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating losses for Oil Sands operations were $21 million, compared to operating earnings of $801 million in the prior year quarter. The decrease was primarily due to lower price realizations impacted by lower crude oil benchmark prices, partially offset by lower royalties, increased production, and lower operating and transportation expenses as a result of the impact of lower natural gas prices and cost reduction initiatives.

Operating losses for Oil Sands ventures were $29 million, compared to operating earnings of $26 million in the prior year quarter, primarily due to lower price realizations and decreased production.

Production Volumes

(mbbls/d)

Upgraded product (SCO and diesel)

Non-upgraded bitumen

Bitumen production from Oil Sands Base operations is upgraded, while bitumen production from In Situ operations is either upgraded or sold directly to customers, including Suncor's own refineries. Yields of SCO and diesel from Suncor's upgrading process are approximately 79% of bitumen feedstock input.

14 SUNCOR ENERGY INC.

Sales Volumes

Oil Sands operations sales volumes

Sweet SCO

Diesel

Sour SCO

Production volumes for Oil Sands operations increased to 430,300 bbls/d in the third quarter of 2015, compared to 411,700 bbls/d in the prior year quarter. The increase was primarily due to higher In Situ production and reliable operations across all assets, compared to the prior year quarter that was impacted by a weather-related site-wide power outage and unplanned upgrader maintenance. Both quarters included planned upgrader maintenance, which resulted in a slowdown of mining activity. The 2015 planned upgrader maintenance was completed in the fourth quarter of 2015.

Sales volumes for Oil Sands operations increased to an average of 429,900 bbls/d in the third quarter of 2015, up from 420,000 bbls/d in the prior year quarter, due to higher production volumes.

Inventory levels in the third quarter of 2015 remained relatively flat as compared to the prior year quarter.

Suncor's share of Syncrude production decreased to 28,100 bbls/d in the third quarter of 2015, compared to 29,400 bbls/d in the prior year quarter. The decrease was primarily due to a fire that occurred at Syncrude's Mildred Lake upgrader during the third quarter of 2015. Subsequent to the quarter end, production was impacted by further operational issues that delayed a return to normal production.

Bitumen Production

Bitumen production (mbbls/d)

Bitumen ore mined (thousands of tonnes per day)

Bitumen ore grade quality (bbls/tonne)

Bitumen production Firebag (mbbls/d)

Bitumen production MacKay River (mbbls/d)

Total In Situ bitumen production

Steam-to-oil ratio Firebag

Steam-to-oil ratio MacKay River

Oil Sands Base bitumen production from mining and extraction activities increased to an average of 303,300 bbls/d in the third quarter of 2015 from 296,900 bbls/d in the prior year quarter. The increase was mainly a result of stronger reliability in the third quarter of 2015.

In Situ bitumen production increased to 219,100 bbls/d in the third quarter of 2015, compared to 199,100 bbls/d in the prior year quarter. The increase was primarily driven by production at Firebag as a result of strong reliability and infill well performance, and favourable steam-to-oil ratios. Production at MacKay River decreased to 27,400 bbls/d in the third

quarter of 2015 from 28,200 bbls/d in the prior year quarter. The decrease was primarily due to planned maintenance that commenced during the third quarter of 2015.

Firebag's steam-to-oil ratio decreased to 2.6 from 2.8 in the prior year quarter, due to strong infill well performance and improved reservoir performance. The steam-to-oil ratio at MacKay River decreased to 2.8 from 3.0 in the prior year quarter, as the prior year required additional steam for the commissioning of new wells.

Price Realizations

Net of transportation costs, but before royalties

($/bbl)

Sweet SCO and diesel

109.13

114.29

Sour SCO and bitumen

Crude sales basket (all products)

Crude sales basket, relative to WTI

(12.86

(16.46

(12.17

(16.02

Syncrude sweet SCO

102.21

106.32

Syncrude, relative to WTI

Average price realizations from Oil Sands operations decreased to $47.93/bbl in the third quarter of 2015 from $89.38/bbl in the prior year quarter, primarily due to the lower WTI benchmark prices, partially offset by favourable exchange rates and the narrowing of crude differentials.

Royalties

Royalties for the Oil Sands segment were lower in the third quarter of 2015 compared to the prior year quarter, primarily due to lower bitumen prices, partially offset by higher production.

Expenses and Other Factors

Operating and transportation expenses for the third quarter of 2015 decreased from the prior year quarter, primarily due to the impact of lower natural gas prices and cost reduction initiatives. See the Cash Operating Costs Reconciliation section below for further details regarding cash operating costs and non-production costs for Oil Sands operations. Transportation expense for the third quarter of 2015 was higher than the prior year quarter, primarily due to the costs related to increased sales volumes.

DD&A expense for the third quarter of 2015 was higher in comparison to the same period of 2014, mainly due to a larger asset base primarily as a result of assets commissioned in 2014, including well pads and infill wells.

16 SUNCOR ENERGY INC.

Operating, selling and general expense (OS&G)

Syncrude OS&G

Non-production costs

Oil Sands cash operating costs ($/bbl)

Cash operating costs and cash operating costs per barrel are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Significant non-production costs include, but are not limited to, share-based compensation adjustments, research, and the expense recorded as part of a non-monetary arrangement involving a third-party processor.

Other includes the impacts of changes in inventory valuation and operating revenues associated with excess capacity, primarily associated with excess power from cogeneration units.

Cash operating costs per barrel for Oil Sands operations in the third quarter of 2015 decreased to $27.00, compared to $31.10 in the prior year quarter, primarily due to higher production volumes combined with the impact of lower natural gas input costs and cost reduction initiatives. Total cash operating costs decreased to $1.069 billion, despite the increase in production, from $1.178 billion in the prior year quarter.

In the third quarter of 2015, non-production costs, which are excluded from cash operating costs, were lower than the prior year quarter. The decrease was primarily due to cost reduction initiatives, including reductions to discretionary spending, lower expenses related to a gas swap arrangement with a third-party processor, and a decrease in costs associated with future growth activities. These were partially offset by higher share-based compensation expense during the third quarter of 2015.

Other items, which are also excluded from cash operating costs, decreased in the third quarter of 2015 compared to the prior year quarter, primarily due to the impacts of changes in inventory valuations, partially offset by a decrease in operating revenues associated with excess power from cogeneration units as a result of the decrease in power prices.

Fort Hills Acquisition

During the third quarter of 2015, the company agreed to purchase an additional 10% working interest in the Fort Hills oil sands project from Total E&P for $310 million, subject to closing adjustments. Subsequent to the quarter end, the condition relating to the

Competition Act

(Canada) was satisfied. The transaction is expected to close by the end of 2015 and upon closing, Suncor's working interest in the project will increase to 50.8%.

Results for the First Nine Months of 2015

Oil Sands segment operating earnings for the first nine months of 2015 were $119 million, compared to $2.591 billion for the same period in 2014. Operating earnings decreased primarily due to significant declines in crude price realizations and higher DD&A expense, partially offset by increased production at Oil Sands operations, lower royalty expense, and lower operating, selling and general expense.

Cash flow from operations for the first nine months of 2015 was $2.368 billion for the segment, compared to $4.525 billion for the same period in 2014. The decrease in cash flow from operations was mainly due to lower average price realizations, partially offset by higher production volumes, lower royalties and lower operating costs.

Cash operating costs per barrel for Oil Sands operations averaged $27.80 for the first nine months of 2015, a decrease from an average of $33.55 for the first nine months of 2014. The decrease was primarily due to higher production volumes and lower cash operating costs driven by lower natural gas prices, lower maintenance costs as a result of increased reliability, and cost reduction initiatives.

EXPLORATION AND PRODUCTION

Libya impairment

Gain on significant disposals

E&P International

Adjustments to the company's deferred income taxes from a 12% decrease in the U.K. tax rate on oil and gas profits from the North Sea in the first quarter of 2015, and a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.

Non-GAAP financial measures. See also the Non-GAAP Financial Measures Advisory section of this MD&A.

For an explanation of the construction of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this MD&A.

E&P operating losses were $1 million in the third quarter of 2015, compared to operating earnings of $137 million in the prior year quarter.

Operating losses of $5 million for E&P Canada decreased from operating earnings of $122 million in the prior year quarter, primarily due to lower price realizations and a decrease in production, partially offset by lower royalties and operating costs.

Operating earnings of $4 million for E&P International decreased from $15 million in the prior year quarter, primarily due to lower price realizations, partially offset by increased production at Buzzard and the addition of production from Golden Eagle.

18 SUNCOR ENERGY INC.

Terra Nova (mbbls/d)

Hibernia (mbbls/d)

White Rose (mbbls/d)

North America Onshore (mboe/d)

Buzzard (mboe/d)

Golden Eagle (mboe/d)

United Kingdom (mboe/d)

Libya (mbbls/d)

Total Production (mboe/d)

Production mix (liquids/gas) (%)

E&P Canada production averaged 40,600 boe/d in the third quarter of 2015, compared to 49,900 boe/d in the prior year quarter. The decrease was primarily due to natural declines at Hibernia and White Rose. Terra Nova production was impacted by a slow ramp up following the completion of the planned turnaround early in the third quarter of 2015. Terra Nova production was also impacted by planned maintenance in the prior year quarter.

E&P International production averaged 67,100 boe/d in the third quarter of 2015, compared to 28,300 boe/d in the prior year quarter. The increase was primarily due to higher production at Buzzard, where the prior year quarter included planned maintenance, and production from Golden Eagle, which came online in the fourth quarter of 2014. Production in Libya remains impacted by political unrest, with the timing of a return to normal operations remaining uncertain.

E&P Canada Crude oil and natural gas liquids ($/bbl)

109.94

114.68

E&P Canada Natural gas ($/mcfe)

E&P International ($/boe)

106.49

113.51

In the third quarter of 2015, price realizations for crude oil from E&P Canada and E&P International were lower than the prior year quarter, consistent with the...


More